U.S. patent application number 14/903765 was filed with the patent office on 2016-06-16 for fracturing or gravel-packing fluid with cmhec in brine.
The applicant listed for this patent is HALLIBURTON ENRGY SERVICES, INC.. Invention is credited to Tingji Tang, Loan Vo.
Application Number | 20160168455 14/903765 |
Document ID | / |
Family ID | 52461818 |
Filed Date | 2016-06-16 |
United States Patent
Application |
20160168455 |
Kind Code |
A1 |
Vo; Loan ; et al. |
June 16, 2016 |
FRACTURING OR GRAVEL-PACKING FLUID WITH CMHEC IN BRINE
Abstract
A method of treating a treatment zone of a subterranean
formation penetrated by a wellbore of a well, the method including
the steps of: (A) forming a treatment fluid comprising: (i) an
aqueous phase comprising water having at least 1,000 ppm total
dissolved inorganic salts; (ii) a carboxymethyl hydroxyethyl
cellulose, wherein: (a) the carboxymethyl hydroxyethyl cellulose
has a carboxymethyl degree of substitution is in the range of about
0.3 to about 0.45 per glucopyranose unit in the polymer; and (b)
the carboxymethyl hydroxyethyl cellulose has a hydroxyethyl
molecular substitution is in the range of about 2.1 to about 2.8
per glucopyranose unit in the polymer; and (iii) a breaker for the
carboxymethyl hydroxyethyl cellulose; and (B) introducing the
treatment fluid into the treatment zone. In embodiments, the
carboxymethyl hydroxyethyl cellulose may or may not be
crosslinked.
Inventors: |
Vo; Loan; (Houston, TX)
; Tang; Tingji; (Spring, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENRGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Family ID: |
52461818 |
Appl. No.: |
14/903765 |
Filed: |
August 9, 2013 |
PCT Filed: |
August 9, 2013 |
PCT NO: |
PCT/US2013/054258 |
371 Date: |
January 8, 2016 |
Current U.S.
Class: |
507/201 ;
507/215 |
Current CPC
Class: |
C08L 1/284 20130101;
C08L 1/286 20130101; C09K 8/68 20130101; C08L 1/28 20130101; C09K
8/90 20130101; C09K 2208/24 20130101; C09K 2208/26 20130101 |
International
Class: |
C09K 8/90 20060101
C09K008/90; C09K 8/68 20060101 C09K008/68 |
Claims
1. A method of treating a treatment zone of a subterranean
formation penetrated by a wellbore of a well, the method
comprising: (A) forming a treatment fluid comprising: (i) an
aqueous phase comprising water having at least 1,000 ppm total
dissolved inorganic salts; (ii) a carboxymethyl hydroxyethyl
cellulose, wherein: (a) the carboxymethyl hydroxyethyl cellulose
has a carboxymethyl degree of substitution is in the range of about
0.3 to about 0.45 per glucopyranose unit in the polymer; and (b)
the carboxymethyl hydroxyethyl cellulose has a hydroxyethyl
molecular substitution is in the range of about 2.1 to about 2.8
per glucopyranose unit in the polymer; and (c) the treatment fluid
is substantially free of any crosslinker for the carboxymethyl
hydroxyethyl cellulose; and (iii) a breaker for the carboxymethyl
hydroxyethyl cellulose; and (B) introducing the treatment fluid
into the treatment zone.
2. The method according to claim 1, wherein the aqueous phase has
at least 1,000 ppm of dissolved divalent cations.
3. The method according to claim 2, wherein the aqueous phase has
at least 25,000 ppm total dissolved inorganic salts.
4. The method according to claim 1, wherein the treatment fluid is
water-based.
5. The method according to claim 1, wherein the breaker is selected
from the group consisting of an oxidizer, an enzyme, or an
acid.
6. The method according to claim 4, wherein the breaker comprises a
delayed release breaker.
7. The method according to claim 5, wherein the breaker is
encapsulated
8. The method according to claim 1, wherein the treatment fluid is
aged less than 24 hours prior to introducing into the treatment
zone.
9. The method according to claim 1, wherein the treatment fluid
additionally comprises a particulate selected from the group
consisting of: proppant and gravel.
10. The method according to claim 1, wherein the well is a
production well.
11. A method of treating a treatment zone of a subterranean
formation penetrated by a wellbore of a well, the method
comprising: (A) forming a treatment fluid comprising: (i) an
aqueous phase comprising water having at least 1,000 ppm total
dissolved inorganic salts; (ii) a carboxymethyl hydroxyethyl
cellulose, wherein: (a) the carboxymethyl hydroxyethyl cellulose
has a carboxymethyl degree of substitution is in the range of about
0.3 to about 0.45 per glucopyranose unit in the polymer; and (b)
the carboxymethyl hydroxyethyl cellulose has a hydroxyethyl
molecular substitution is in the range of about 2.1 to about 2.8
per glucopyranose unit in the polymer; (iii) a crosslinker for the
carboxymethyl hydroxyethyl cellulose, wherein the crosslinker
comprises a polyvalent cation; and (iv) a breaker for the
carboxymethyl hydroxyethyl cellulose; wherein the aqueous phase has
or is adjusted to have an initial pH in the range of 4.5-6.5; and
(B) introducing the treatment fluid into the treatment zone.
12. The method according to claim 11, wherein the aqueous phase has
at least 1,000 ppm of dissolved divalent cations.
13. The method according to claim 12, wherein the aqueous phase has
at least 25,000 ppm total dissolved inorganic salts.
14. The method according to claim 11, wherein the treatment fluid
is water-based.
15. The method according to claim 11, wherein the breaker is
selected from the group consisting of an oxidizer, an enzyme, or an
acid.
16. The method according to claim 15, wherein the breaker comprises
a delayed release breaker.
17. The method according to claim 15, wherein the breaker is
encapsulated
18. The method according to claim 11, wherein the treatment fluid
is aged less than 24 hours prior to introducing into the treatment
zone.
19. The method according to claim 11, wherein the treatment fluid
additionally comprises a particulate selected from the group
consisting of: proppant and gravel.
20. The method according to claim 11, wherein the well is a
production well.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not applicable.
TECHNICAL FIELD
[0002] This disclosure is in the field of producing crude oil or
natural gas from subterranean formations. More specifically, the
disclosure generally relates to fluids and methods of fracturing a
treatment zone of a subterranean formation penetrated by a wellbore
of a well.
BACKGROUND
[0003] The demand for fresh water for oilfield operations has
skyrocketed as a result of the boom in hydraulic fracturing for
shale plays. A typical hydraulic fracturing treatment may consume,
on average, three to five million gallons of water (usually
freshwater). This is particularly problematic offshore, where
freshwater must be transported to the well site, whereas seawater
is readily available, if it could be used to formulate a good
fracturing fluid.
[0004] For additional reasons it is often desirable to form and use
a fracturing fluid having a high content of inorganic salt, whether
on land or offshore. For example, salt curbs bacterial action. Salt
provides weight (that is, density) to a treatment fluid. Salt (e.g.
KCl) usually reduces damage to production sands containing
swellable clay.
[0005] Not many polymers perform well in brine, however, and even
fewer perform well in hard brine such as seawater, which include a
high concentration of divalent metal ions such as magnesium and
calcium.
GENERAL DESCRIPTION OF EMBODIMENTS
[0006] Carboxymethylhydroxyethyl cellulose ("CMHEC") is a cellulose
derivative having two different substituents bound onto some of the
hydroxy groups of the glucopyranose monomers that make up the
cellulose backbone: one is the carboxymethyl ("CM") group, and the
other is the hydroxyethyl ("HE") group.
[0007] Use of CMHEC in fracturing fluids has offered many
advantages over traditional guar-based frac fluids. For example,
CMHEC, as it compares to a traditional guar-based fluid, provides
superior cleanliness and reduced cost. Most commercially available
guar has between 3% and 10% by weight insoluble residue, whereas
CMHEC has less than 1% by weight insoluble residue, that is,
polymeric material that does not fully hydrate. CMHEC provides
improved cleanup and enhanced proppant pack, sand pack, or core
regained permeability, which ultimately leads to enhanced oil or
gas production from stimulation treatments. Another property that
makes CMHEC a great candidate for use in treatments fluids for
fracturing or frac-packing is that CMHEC has shown to provide
greater proppant or gravel suspension as compared to guar-based
fluids or viscoelastic (VES) fluids.
[0008] In comparison to fracturing fluids that utilize
carboxymethyl cellulose ("CMC"), which also offer the above
advantages of cleanliness, CMHEC-based fluids offer enhanced
performance and provide superior salt tolerance. Thus, these fluids
have potential for use with alternative sources of water.
[0009] CMHEC-based fluid systems can be used in brackish water,
seawater, or brine, even hard brine; however, the particular CMHEC
should be selected for use in hard brine. These systems can be
especially suitable for offshore applications using seawater as
well as those onshore involving anything from pond to sewage to
recycled flowback or produced waters, which often have dissolved
salts. This disclosure can decrease the demand of fresh water
required for fracturing applications while providing a clean and
reliable fracturing fluid.
[0010] The carboxy-substituted cellulose ethers, such as CMHEC and
CMC, are usually commercially available as the alkali metal salt,
usually the sodium salt. However, the metal is seldom referred to
and they are commonly referred to as CMC, CMHEC. Unless otherwise
stated, it should be understood that these are typically obtained
as the alkali metal salt. Of course, the carboxylate form (alkali
metal salt) can be easily converted to the carboxylic acid form
depending on the pH of an aqueous phase in which the polymeric
material is dispersed or dissolved.
[0011] The molecular structure of carboxymethyl hydroxyethyl
cellulose is related to its performance in a hydraulic fracturing
fluid. Understanding the biopolymer at its molecular level not only
helps explain the current rheological properties of a CMHEC fluid
but also allow chemists to tailor the chemistry of the polymer to
deliver specific performances for specific applications.
[0012] It is believed that on which hydroxyl groups the CM or HE
groups are substituted and how many of these substituents per
glucopyranose monomer unit are critical to the polymer's physical
and chemical properties and the rheological properties of a
CMHEC-based fluid.
[0013] The terms "DS" and "MS" are abbreviations for "degree of
substitution" and "molar substitution," respectively. Three
hydroxyl groups are in each anhydroglucose unit in the cellulose
molecule. DS is the average number of hydroxyl groups substituted
in the cellulose per anhydroglucose unit. Thus, the DS of a
cellulose derivative can be no higher than 3. MS is the average
number of moles of reactant combined with the cellulose per
anhydroglucose unit. For the alkyl, carboxyalkyl, or acyl
derivatives of cellulose, the DS and the MS are the same. For the
hydroxyalkyl derivatives of cellulose, the MS is generally greater
than the DS. The reason for this is that each time a hydroxyalkyl
group is reacted with the cellulose molecule, an additional
hydroxyl group is formed which itself is capable of
hydroxyalkylation. As a result of this, side chains of considerable
length may form on the cellulose molecule. The MS/DS ratio
represents the average length of these side chains. See, for
example, Polymer Modification: Principles, Techniques, and
Applications, edited by John J. Meister, CRC Press, 2000, pages
49-52.
[0014] In general, the carboxymethyl DS of the CMHEC can be in a
broad range of about 0.1 to about 1.0 and the hydroxyethyl MS can
be in the range of about 0.1 to about 3. However, examples of
hydration of several aqueous CMHEC-based fluid wherein the CMHEC
has varying degrees of CM-DS and HE-MS substitutions leads to
several critical conclusion about the relationship of the chemistry
of the polymer at the molecular level and its performance as a
fracturing fluid as well as its tolerance in an ionic solution,
especially a hard brine such as seawater: (A) CMHEC with
carboxymethyl degree of substitution (CM-DS) between about 0.3 to
about 0.45 per glucopyranose unit in polymer provides good salt
tolerance even in a hard brine such as seawater and also provides
good cross-linking efficiency; and (B) CMHEC with hydroxyethyl
molecular substitution (HE-MS) between about 2.1 to about 2.8 per
glucopyranose unit in polymer provides good salt tolerance even in
a hard brine such as seawater. The presence of hydroxyethyle groups
along the side chains will help to improve the hydration kinetics
of CMHEC in water thus decrease the hydration time. The
hydrophobicity of the hydroxylethyl groups will also improve the
thermal stability of gels and thus could be applied in wells with
higher BHST. In addition, it is believed that random CM-DS is
better than block CM substitution. The CMHEC examples were obtained
from a commercial supplier, which products are conventionally used
for hair conditioner or in the food industry.
[0015] For example, the concentration of gel balls of the polymer
that remained unhydrated in seawater decreases as the HE-MS
increases. Without necessarily being limited by any theory, it is
further believed that within this HE-MS range, the higher the
molecular substitution of hydroxyethyl group, the more the polymer
strand untangled, minimizing crystalline segment and blockness in
the polymer, leading to easier hydration and minimizing unhydrated
gel balls.
[0016] The CMHEC-based fluid: is a clean, non-damaging, less
expensive alternative to a guar-based fluid; has greater salt
tolerance than other "clean" fluid systems (such as CMC-based
fluids); and is robust, versatile, and has potential to work in a
variety of water types.
[0017] A method of treating a treatment zone of a subterranean
formation penetrated by a wellbore of a well is provided, the
method including: (A) forming a treatment fluid comprising: (i) an
aqueous phase comprising water having at least 1,000 ppm total
dissolved inorganic salts; (ii) a carboxymethyl hydroxyethyl
cellulose, wherein: (a) the carboxymethyl hydroxyethyl cellulose
has a carboxymethyl degree of substitution is in the range of about
0.3 to about 0.45 per glucopyranose unit in the polymer; and (b)
the carboxymethyl hydroxyethyl cellulose has a hydroxyethyl
molecular substitution is in the range of about 2.1 to about 2.8
per glucopyranose unit in the polymer; and (iii) a breaker for the
carboxymethyl hydroxyethyl cellulose; and (B) introducing the
treatment fluid into the treatment zone.
[0018] In an embodiment, the treatment fluid is substantially free
of any crosslinker for the carboxymethyl hydroxyethyl cellulose.
Such an embodiment of the CMHEC in a brine as a non-crosslinked
fluid (sometimes referred to as a "linear gel") can be used, for
example, as a pad fluid as part of a method of hydraulic fracturing
in a treatment zone. As used herein, "substantially free" means
having less of any crosslinker that would be effective to increase
the viscosity of the fluid by more than 10% relative to an
otherwise same CMHEC-based fluid that is completely
non-crosslinked. In such an embodiment, the treatment fluid is
preferably essentially free of any crosslinker for the
carboxymethyl hydroxyethyl cellulose. As used herein, "essentially
free" means having less of any crosslinker that would be effective
to increase the viscosity of the fluid by more than 5% relative to
an otherwise same CMHEC-based fluid that is completely
non-crosslinked. More preferably, in such an embodiment, the
treatment fluid is completely free of any crosslinker for the
carboxymethyl hydroxyethyl cellulose. In such an embodiment, the
aqueous phase preferably has an initial pH greater than about 5.
More preferably, the aqueous phase has a pH in the range of about 5
to about 9. Most preferably, the aqueous phase has an initial pH in
the rate of about 6 to about 8.
[0019] In another embodiment, the treatment fluid includes a
crosslinker for the carboxymethyl hydroxyethyl cellulose, wherein
the crosslinker comprises a polyvalent cation. As used herein,
"polyvalent" means having a valence state of 3 or greater. In such
an embodiment, the polyvalent cation is preferably chelated.
Preferably, the polyvalent cation is selected from the group
consisting of aluminum, zirconium, titanium, and any combination
thereof. In such an embodiment, the aqueous phase preferably has an
initial pH greater than about 5. More preferably, the aqueous phase
has a pH in the range of about 5 to about 6.5. For a crosslinked
fracturing fluid or gravel-packing fluid, it is desirable for the
treatment fluid to crosslink within a matter of minutes of forming
the treatment fluid, for example, in less than about 10
minutes.
[0020] These and other embodiments of the disclosure will be
apparent to one skilled in the art upon reading the following
detailed description. While the disclosure is susceptible to
various modifications and alternative forms, specific embodiments
thereof will be described in detail and shown by way of example. It
should be understood, however, that it is not intended to limit the
disclosure to the particular forms disclosed.
BRIEF DESCRIPTION OF THE DRAWING
[0021] The accompanying drawing is incorporated into the
specification to help illustrate examples according to a presently
preferred embodiment of the disclosure.
[0022] FIG. 1 is a photograph of CMHEC with CM-DS in the range of
about 0.30 to about 0.35 and HE-MS in the range of about 2.1 to
about 2.2 in synthetic seawater on a microscope slide at 60.times.
magnification;
[0023] FIG. 2 is a photograph of CMHEC with CM-DS in the range of
about 0.45 to about 0.6 and HE-MS in the range of about 2.4 to
about 2.6 in synthetic seawater on a microscope slide at 60.times.
magnification; and
[0024] FIG. 3 is a photograph of CMHEC with CM-DS in the range of
about 0.35 to about 0.45 and HE-MS in the range of about 2.8 to
about 2.9 in synthetic seawater on a microscope slide at 60.times.
magnification.
DETAILED DESCRIPTION OF PRESENTLY PREFERRED EMBODIMENTS AND BEST
MODE
Definitions and Usages
[0025] General Interpretation
[0026] The words or terms used herein have their plain, ordinary
meaning in the field of this disclosure, except to the extent
explicitly and clearly defined in this disclosure or unless the
specific context otherwise requires a different meaning.
[0027] The words "comprising," "containing," "including," "having,"
and all grammatical variations thereof are intended to have an
open, non-limiting meaning. For example, a composition comprising a
component does not exclude it from having additional components, an
apparatus comprising a part does not exclude it from having
additional parts, and a method having a step does not exclude it
having additional steps. When such terms are used, the
compositions, apparatuses, and methods that "consist essentially
of" or "consist of" the specified components, parts, and steps are
specifically included and disclosed. As used herein, the words
"consisting essentially of," and all grammatical variations thereof
are intended to limit the scope of a claim to the specified
materials or steps and those that do not materially affect the
basic and novel characteristic(s) of the claimed invention.
[0028] The indefinite articles "a" or "an" mean one or more than
one of the component, part, or step that the article
introduces.
[0029] Whenever a numerical range of degree or measurement with a
lower limit and an upper limit is disclosed, any number and any
range falling within the range is also intended to be specifically
disclosed. For example, every range of values (in the form "from a
to b," or "from about a to about b," or "from about a to b," "from
approximately a to b," and any similar expressions, where "a" and
"b" represent numerical values of degree or measurement) is to be
understood to set forth every number and range encompassed within
the broader range of values.
[0030] Oil and Gas Reservoirs
[0031] In the context of production from a well, "oil" and "gas"
are understood to refer to crude oil and natural gas, respectively.
Oil and gas are naturally occurring hydrocarbons in certain
subterranean formations.
[0032] A "subterranean formation" is a body of rock that has
sufficiently distinctive characteristics and is sufficiently
continuous for geologists to describe, map, and name it.
[0033] A subterranean formation having a sufficient porosity and
permeability to store and transmit fluids is sometimes referred to
as a "reservoir."
[0034] A subterranean formation containing oil or gas may be
located under land or under the seabed off shore. Oil and gas
reservoirs are typically located in the range of a few hundred feet
(shallow reservoirs) to a few tens of thousands of feet (ultra-deep
reservoirs or source rocks such as shale formation) below the
surface of the land or seabed.
[0035] Well Servicing
[0036] To produce oil or gas from a reservoir, a wellbore is
drilled into a subterranean formation, which may be the reservoir
or adjacent to the reservoir.
[0037] Generally, well services include a wide variety of
operations that may be performed in oil, gas, geothermal, or water
wells, such as drilling, cementing, completion, and intervention.
Well services are designed to facilitate or enhance the production
of desirable fluids such as oil or gas from or through a
subterranean formation. A well service usually involves introducing
a fluid into a well.
[0038] Drilling, completion, and intervention operations can
include various types of treatments that are commonly performed on
a well or subterranean formation. During completion or
intervention, stimulation is a type of treatment performed to
enhance or restore the productivity of oil and gas from a well.
Stimulation treatments fall into two main groups: hydraulic
fracturing and matrix treatments. Fracturing treatments are
performed above the fracture pressure of the subterranean formation
to create or extend a highly permeable flow path between the
formation and the wellbore. Matrix treatments are performed below
the fracture pressure of the formation. Other types of completion
or intervention treatments can include, for example, gravel
packing, consolidation, and controlling excessive water
production.
[0039] Wells and Fluids
[0040] A "well" includes a wellhead and at least one wellbore from
the wellhead penetrating the earth. The "wellhead" is the surface
termination of a wellbore, which surface may be on land or on a
seabed.
[0041] A "well site" is the geographical location of a wellhead of
a well. It may include related facilities, such as a tank battery,
separators, compressor stations, heating or other equipment, and
fluid pits. If offshore, a well site can include a platform.
[0042] The "wellbore" refers to the drilled hole, including any
cased or uncased portions of the well or any other tubulars in the
well. A wellbore can have portions that are vertical, horizontal,
or anything in between, and it can have portions that are straight,
curved, or branched. As used herein, "uphole," "downhole," and
similar terms are relative to the direction of the wellhead,
regardless of whether a wellbore portion is vertical or
horizontal.
[0043] A wellbore can be used as a production or injection
wellbore. A production wellbore is used to produce hydrocarbons
from the reservoir. An injection wellbore is used to inject a
fluid, for example, liquid water or steam, to drive oil or gas to a
production wellbore.
[0044] As used herein, introducing "into a well" means introducing
at least into and through the wellhead. According to various
techniques known in the art, tubulars, equipment, tools, or fluids
can be directed from the wellhead into any desired portion of the
wellbore.
[0045] As used herein, the word "tubular" means any kind of
structural body in the general form of a tube. Examples of tubulars
in oil wells include, but are not limited to, a drill pipe, a
casing, a tubing string, a coil tubing, a line pipe, and a
transportation pipe.
[0046] As used herein, unless the context otherwise requires, a
treatment fluid refers to the specific properties and composition
of a fluid at the time the fluid is being introduced into a well.
In addition, it should be understood that, during the course of a
well operation such as drilling, cementing, completion, or
intervention, or during a specific treatment, the specific
properties and composition of a type of fluid can be varied or
several different types of fluids can be used.
[0047] For example, the compositions can be varied to adjust
viscosity or elasticity of the fluids to accommodate changes in the
concentrations of particulate to be carried downhole. It can also
be desirable to accommodate expected changes in temperatures
encountered by the fluids during the course of the treatment. By
way of another example, it can be desirable to accommodate the
longer duration that an earlier-introduced treatment fluid may need
to maintain viscosity before breaking compared to the shorter
duration that a later-introduced treatment fluid may need to
maintain viscosity before breaking. Changes in concentration of a
particulate, viscosity-increasing agent, breaker, or other
additives in the various treatment fluids of a treatment operation
can be made in stepped changes of concentrations or ramped changes
of concentrations.
[0048] As used herein, the word "treatment" refers to any treatment
for changing a condition of a portion of a wellbore or a
subterranean formation adjacent a wellbore; however, the word
"treatment" does not necessarily imply any particular treatment
purpose. A treatment usually involves introducing a fluid for the
treatment, in which case it may be referred to as a treatment
fluid, into a well. As used herein, a "treatment fluid" is a fluid
used in a treatment. The word "treatment" in the term "treatment
fluid" does not necessarily imply any particular treatment or
action by the fluid.
[0049] In the context of a well or wellbore, a "portion" or
"interval" refers to any downhole portion or interval along the
length of a wellbore.
[0050] A "zone" refers to an interval of rock along a wellbore that
is differentiated from uphole and downhole zones based on
hydrocarbon content or other features, such as permeability,
composition, perforations, or other fluid communication with the
wellbore, faults, or fractures. A zone of a wellbore that
penetrates a hydrocarbon-bearing zone that is capable of producing
hydrocarbon is referred to as a "production zone." A "treatment
zone" refers to an interval of rock along a wellbore into which a
fluid is directed to flow from the wellbore. As used herein, "into
a treatment zone" means into and through the wellhead and,
additionally, through the wellbore and into the treatment zone.
[0051] A "design" refers to the estimate or measure of one or more
parameters planned or expected for a particular fluid or stage of a
well service or treatment. For example, a fluid can be designed to
have components that provide a minimum density or viscosity for at
least a specified time under expected downhole conditions. A well
service may include design parameters such as fluid volume to be
pumped, required pumping time for a treatment, or the shear
conditions of the pumping.
[0052] The term "design temperature" refers to an estimate or
measurement of the actual temperature at the downhole environment
during the time of a treatment. For example, the design temperature
for a well treatment takes into account not only the bottom hole
static temperature ("BHST"), but also the effect of the temperature
of the fluid on the BHST during treatment. The design temperature
for a fluid is sometimes referred to as the bottom hole circulation
temperature ("BHCT"). Because fluids may be considerably cooler
than BHST, the difference between the two temperatures can be quite
large. Ultimately, if left undisturbed a subterranean formation
will return to the BHST.
[0053] Particles and Particulates
[0054] As used herein, a "particle" refers to a body having a
finite mass and sufficient cohesion such that it can be considered
as an entity but having relatively small dimensions. A particle can
be of any size ranging from molecular scale to macroscopic,
depending on context.
[0055] As used herein, particulate or particulate material refers
to matter in the physical form of distinct particles in a solid or
liquid state (which means such an association of a few atoms or
molecules). As used herein, a particulate is a grouping of
particles having similar chemical composition and particle size
ranges anywhere in the range of about 0.5 micrometer (500 nm), for
example, microscopic clay particles, to about 3 millimeters, for
example, large grains of sand.
[0056] A particulate can be of solid or liquid particles. As used
herein, however, unless the context otherwise requires, particulate
refers to a solid particulate.
[0057] It should be understood that the terms "particle" and
"particulate," includes all known shapes of particles including
substantially rounded, spherical, oblong, ellipsoid, rod-like,
fiber, polyhedral (such as cubic materials), etc., and mixtures
thereof. For example, the term "particulate" as used herein is
intended to include solid particles having the physical shape of
platelets, shavings, flakes, ribbons, rods, strips, spheroids,
toroids, pellets, tablets or any other physical shape.
[0058] As used herein, a fiber is a particle or grouping of
particles having an aspect ratio L/D greater than 5/1.
[0059] A particulate will have a particle size distribution
("PSD"). As used herein, "the size" of a particulate can be
determined by methods known to persons skilled in the art.
[0060] One way to measure the approximate particle size
distribution of a solid particulate is with graded screens. A solid
particulate material will pass through some specific mesh (that is,
have a maximum size; larger pieces will not fit through this mesh)
but will be retained by some specific tighter mesh (that is, a
minimum size; pieces smaller than this will pass through the mesh).
This type of description establishes a range of particle sizes. A
"+" before the mesh size indicates the particles are retained by
the sieve, while a "-" before the mesh size indicates the particles
pass through the sieve. For example, -70/+140 means that 90% or
more of the particles will have mesh sizes between the two
values.
[0061] Particulate materials are sometimes described by a single
mesh size, for example, 100 U.S. Standard mesh. If not otherwise
stated, a reference to a single particle size means about the
mid-point of the industry-accepted mesh size range for the
particulate.
[0062] Dispersions and Solutions
[0063] A dispersion is a system in which particles of a substance
of one chemical composition and physical state are dispersed in
another substance of a different chemical composition or physical
state. In addition, phases can be nested. If a substance has more
than one phase, the most external phase is referred to as the
continuous phase of the substance as a whole, regardless of the
number of different internal phases or nested phases.
[0064] A dispersion can be classified in different ways, including,
for example, based on the size of the dispersed particles, the
uniformity or lack of uniformity of the dispersion, and, if a
fluid, by whether or not precipitation occurs.
[0065] A dispersion is considered to be heterogeneous if the
dispersed particles are not dissolved and are greater than about 1
nanometer in size. (For reference, the diameter of a molecule of
toluene is about 1 nm and a molecule of water is about 0.3 nm).
[0066] Heterogeneous dispersions can have gas, liquid, or solid as
an external phase. For example, in a case where the dispersed-phase
particles are liquid in an external phase that is another liquid,
this kind of heterogeneous dispersion is more particularly referred
to as an emulsion. A solid dispersed phase in a continuous liquid
phase is referred to as a sol, suspension, or slurry, partly
depending on the size of the dispersed solid particulate.
[0067] A dispersion is considered to be homogeneous if the
dispersed particles are dissolved in solution or the particles are
less than about 1 nanometer in size. Even if not dissolved, a
dispersion is considered to be homogeneous if the dispersed
particles are less than about 1 nanometer in size.
[0068] A solution is a special type of homogeneous mixture. A
solution is considered homogeneous: (a) because the ratio of solute
to solvent is the same throughout the solution; and (b) because
solute will never settle out of solution, even under powerful
centrifugation, which is due to intermolecular attraction between
the solvent and the solute. An aqueous solution, for example,
saltwater, is a homogenous solution in which water is the solvent
and salt is the solute.
[0069] Hydratability or Solubility
[0070] As referred to herein, "hydratable" means capable of being
hydrated by contacting the hydratable material with water.
Regarding a hydratable material that includes a polymer, this
means, among other things, to associate sites on the polymer with
water molecules and to unravel and extend the polymer chain in the
water.
[0071] The term "solution" is intended to include not only true
molecular solutions but also dispersions of a polymer wherein the
polymer is so highly hydrated as to cause the dispersion to be
visually clear and having essentially no particulate matter visible
to the unaided eye. The term "soluble" is intended to have a
meaning consistent with these meanings of solution.
[0072] A substance is considered to be "soluble" in a liquid if at
least 10 grams of the substance can be hydrated or dissolved in one
liter of the liquid when tested at 77.degree. F. and 1 atmosphere
pressure for 2 hours, considered to be "insoluble" if less than 1
gram per liter, and considered to be "sparingly soluble" for
intermediate solubility values.
[0073] As will be appreciated by a person of skill in the art, the
hydratability, dispersibility, or solubility of a substance in
water can be dependent on the salinity, pH, or other substances in
the water. Accordingly, the salinity, pH, and additive selection of
the water can be modified to facilitate the hydratability,
dispersibility, or solubility of a substance in aqueous solution.
To the extent not specified, the hydratability, dispersibility, or
solubility of a substance in water is determined in deionized
water, at neutral pH, and without any other additives.
[0074] As used herein, "salt tolerance" of a polymeric material
means it hydrates well in the presence of dissolved salts to
provide viscosity, for example, in 2% KCl or in presence of
divalent ions, for example, in synthetic seawater.
[0075] The "source" of a chemical species in a solution or in a
fluid composition can be a material or substance that is itself the
chemical species, or that makes the chemical species chemically
available immediately, or it can be a material or substance that
gradually or later releases the chemical species to become
chemically available in the solution or the fluid.
[0076] Fluids
[0077] A fluid can be a homogeneous or heterogeneous. In general, a
fluid is an amorphous substance that is or has a continuous phase
of particles that are smaller than about 1 micrometer that tends to
flow and to conform to the outline of its container.
[0078] Every fluid inherently has at least a continuous phase. A
fluid can have more than one phase. The continuous phase of a
treatment fluid is a liquid under Standard Laboratory
Conditions.
[0079] The term "water" is used generally herein to include fresh
water or brine, unless the context otherwise requires.
[0080] As used herein, the term "brine" is intended to include,
unless the context otherwise requires, any aqueous solution having
greater than 1,000 ppm total dissolved inorganic salts. Oil field
brines commonly contain varying concentrations of inorganic salts,
e.g., sodium chloride, calcium chloride, and magnesium salts.
Aqueous solutions are frequently modified by addition of potassium
chloride to stabilize the subsurface clay. Accordingly, potassium
chloride is frequently encountered in brines.
[0081] As used herein, the term "hard brine" is intended to
include, unless the context otherwise requires, any aqueous
solution having greater than 1,000 ppm total dissolved divalent
inorganic salts, such as magnesium or calcium. For example, a hard
brine can have about 1,000 ppm to about 16,000 ppm divalent cations
such calcium ions.
[0082] As used herein, a "water-based" fluid means that water or an
aqueous solution is the dominant material of the continuous phase,
that is, greater than 50% by weight, of the continuous phase of the
fluid based on the combined weight of water and any other solvents
in the phase (that is, excluding the weight of any dissolved
solids).
[0083] In contrast, an "oil-based" fluid means that oil is the
dominant material by weight of the continuous phase of the fluid.
In this context, the oil of an oil-based fluid can be any oil.
[0084] Gels and Deformation
[0085] Technically, a "gel" is a semi-solid, jelly-like physical
state or phase that can have properties ranging from soft and weak
to hard and tough. Shearing stresses below a certain finite value
fail to produce permanent deformation. The minimum shear stress
which will produce permanent deformation is referred to as the
shear strength or gel strength of the gel.
[0086] The physical state of a gel is formed by a network of
interconnected molecules, such as a crosslinked polymer or a
network of micelles in a continuous liquid phase. The network gives
a gel phase its structure and an apparent yield point. At the
molecular level, a gel is a dispersion in which both the network of
molecules is continuous and the liquid is continuous. A gel is
sometimes considered as a single phase.
[0087] A hydrogel is a gel state having a network of polymer chains
that are hydrophilic and for which water is the dispersion medium.
In some cases, a "hydrogel" refers to a natural or synthetic
polymeric material that is a highly absorbent and that can form
such a gel.
[0088] In the oil and gas industry, however, the term "gel" may be
used to refer to any fluid having a viscosity-increasing agent,
regardless of whether it is a viscous fluid or meets the technical
definition for the physical state of a gel. A "base gel" is a term
used in the field for a fluid that includes a viscosity-increasing
agent, such as guar or other polymer, but that excludes
crosslinking agents. Typically, a base gel is mixed with another
fluid containing a crosslinker, wherein the mixture is adapted to
form a crosslinked gel. Similarly, a "crosslinked gel" may refer to
a substance having a viscosity-increasing agent that is
crosslinked, regardless of whether it is a viscous fluid or meets
the technical definition for the physical state of a gel.
[0089] As used herein, a substance referred to as a "gel" is
subsumed by the concept of "fluid" if it is a pumpable fluid.
[0090] Viscosity Measurements (For Example, for Hydraulic
Fracturing or Gravel Packing)
[0091] There are numerous ways of measuring and modeling viscous
properties, and new developments continue to be made. The methods
depend on the type of fluid for which viscosity is being measured.
A typical method for quality assurance or quality control (QA/QC)
purposes uses a couette device, such as a FANN.TM. Model 35 or
Model 50 viscometer or a CHANDLER.TM. Model 5550 HPHT viscometer.
Such a viscometer measures viscosity as a function of time,
temperature, and shear rate. The viscosity-measuring instrument can
be calibrated using standard viscosity silicone oils or other
standard viscosity fluids.
[0092] A substance is considered to be a fluid if it has an
apparent viscosity less than 5,000 mPas (cP) (independent of any
gel characteristic). For reference, the viscosity of pure water is
about 1 mPas (cP).
[0093] As used herein, for the purposes of hydraulic fracturing a
fluid is considered to be "viscous" if it has an apparent viscosity
of 200 mPas (cP) at 40 s.sup.-1 shear rate or higher. The viscosity
of a viscous fluid is considered to break or be broken if the
viscosity is greatly reduced. Preferably, although not necessarily
for all applications depending on how high the initial viscosity of
the fluid, the viscous fluid breaks to a viscosity of less than 50%
of the viscosity of the maximum viscosity or less than 200 mPas
(cP) at 40 s.sup.-1 shear rate.
[0094] General Measurement Terms
[0095] Unless otherwise specified or unless the context otherwise
clearly requires, any ratio or percentage means by weight.
[0096] Unless otherwise specified or unless the context otherwise
clearly requires, the phrase "by weight of the water" means the
weight of the water of an aqueous phase of the fluid without the
weight of any viscosity-increasing agent, dissolved salt, suspended
particulate, or other materials or additives that may be present in
the water.
[0097] If there is any difference between U.S. or Imperial units,
U.S. units are intended. For example, "GPT" or "gal/Mgal" means
U.S. gallons per thousand U.S. gallons and "ppt" means pounds per
thousand U.S. gallons.
[0098] The barrel ("bbl") is the unit of measure used in the US oil
industry, wherein one barrel equals 42 U.S. gallons. Standards
bodies such as the American Petroleum Institute (API) have adopted
the convention that if oil is measured in oil barrels, it will be
at 14.696 psi and 60.degree. F., whereas if it is measured in cubic
meters, it will be at 101.325 kPa and 15.degree. C. (or in some
cases 20.degree. C.). The pressures are the same but the
temperatures are different--60.degree. F. is 15.56.degree. C.,
15.degree. C. is 59.degree. F., and 20.degree. C. is 68.degree. F.
However, if all that is needed is to convert a volume in barrels to
a volume in cubic meters without compensating for temperature
differences, then 1 bbl equals 0.159 m.sup.3 or 42 U.S.
gallons.
[0099] Unless otherwise specified, mesh sizes are in U.S. Standard
Mesh.
[0100] The micrometer (.mu.m) may sometimes be referred to herein
as a micron.
[0101] The conversion between pound per gallon (lb/gal or ppg) and
kilogram per cubic meter (kg/m.sup.3) is: 1 lb/gal=(0.4536
kg/lb).times.(gal/0.003785 m.sup.3)=120 kg/m.sup.3.
[0102] The conversion between pound per thousand gallons (lb/Mgal)
and kilogram per cubic meter (kg/m.sup.3) is: 1 lb/Mgal=(0.4536
kg/lb).times.(Mgal/3.785 m.sup.3)=0.12 kg/m.sup.3.
[0103] The conversion between pound per barrel (lb/bbl) and
kilogram per cubic meter (kg/m.sup.3) is: 1 lb/bbl=(0.4536
kg/lb).times.(bbl/0.159 m.sup.3)=2.85 kg/m.sup.3.
Hydraulic Fracturing
[0104] The purpose of a hydraulic fracturing treatment is to
provide an improved flow path for oil or gas to flow from a
hydrocarbon-bearing formation to the wellbore. In addition, a
fracturing treatment can facilitate the flow of injected treatment
fluids from the well into the formation. A treatment fluid adapted
for this purpose is sometimes referred to as a fracturing fluid.
The fracturing fluid is pumped at a sufficiently high flow rate and
pressure into the wellbore and into the subterranean formation to
create or enhance one or more fractures in the subterranean
formation. Creating a fracture means making a new fracture in the
formation. Enhancing a fracture means enlarging a pre-existing
fracture in the formation.
[0105] A frac pump is used for hydraulic fracturing. A frac pump is
a high-pressure, high-volume pump. The fracturing fluid may be
pumped down into the wellbore at high rates and pressures, for
example, at a flow rate in excess of 50 barrels per minute (2,100
U.S. gallons per minute) at a pressure in excess of 5,000 pounds
per square inch ("psi"). The pump rate and pressure of the
fracturing fluid may be even higher, for example, flow rates in
excess of 100 barrels per minute and pressures in excess of 10,000
psi are often encountered.
[0106] Fracturing a subterranean formation often uses hundreds of
thousands of gallons of fracturing fluid or more. Further, it is
often desirable to fracture more than one treatment zone of a well.
Therefore, a high volume of fracturing fluids is often used in
fracturing of a well, which means that a low-cost fracturing fluid
is desirable. Because of the ready availability and relative low
cost of water compared to other liquids, among other
considerations, a fracturing fluid is usually water-based.
[0107] The creation or extension of a fracture in hydraulic
fracturing may initially occur suddenly. When this happens, the
fracturing fluid suddenly has a fluid flow path through the
fracture to flow more rapidly away from the wellbore. As soon as
the fracture is created or enhanced, the sudden increase in the
flow of fluid away from the well reduces the pressure in the well.
Thus, the creation or enhancement of a fracture in the formation
may be indicated by a sudden drop in fluid pressure, which can be
observed at the wellhead. After initially breaking down the
formation, the fracture may then propagate more slowly, at the same
pressure or with little pressure increase. It can also be detected
with seismic techniques.
[0108] A newly-created or newly-extended fracture will tend to
close together after the pumping of the fracturing fluid is
stopped. To prevent the fracture from closing, a material is
usually placed in the fracture to keep the fracture propped open
and to provide higher fluid conductivity than the matrix of the
formation. A material used for this purpose is referred to as a
proppant.
[0109] A proppant is in the form of a solid particulate, which can
be suspended in the fracturing fluid, carried downhole, and
deposited in the fracture to form a proppant pack. The proppant
pack props the fracture in an open condition while allowing fluid
flow through the permeability of the pack. The proppant pack in the
fracture provides a higher-permeability flow path for the oil or
gas to reach the wellbore compared to the permeability of the
matrix of the surrounding subterranean formation. This
higher-permeability flow path increases oil and gas production from
the subterranean formation.
[0110] A particulate for use as a proppant is usually selected
based on the characteristics of size range, crush strength, and
solid stability in the types of fluids that are encountered or used
in wells. Preferably, a proppant should not melt, dissolve, or
otherwise degrade from the solid state under the downhole
conditions.
[0111] The proppant is selected to be an appropriate size to prop
open the fracture and bridge the fracture width expected to be
created by the fracturing conditions and the fracturing fluid. If
the proppant is too large, it will not easily pass into a fracture
and will screenout too early. If the proppant is too small, it will
not provide the fluid conductivity to enhance production. See, for
example, W. J. McGuire and V. J. Sikora, "The Effect of Vertical
Fractures on Well Productivity," Trans., AIME (1960) 219, 401-403.
In the case of fracturing relatively permeable or even tight-gas
reservoirs, a proppant pack should provide higher permeability than
the matrix of the formation. In the case of fracturing ultra-low
permeable formations, such as shale formations, a proppant pack
should provide for higher permeability than the naturally occurring
fractures or other micro-fractures of the fracture complexity.
[0112] Appropriate sizes of particulate for use as a proppant are
typically in the range from about 8 to about 100 U.S. Standard
Mesh. A typical proppant is sand-sized, which geologically is
defined as having a largest dimension ranging from about 0.06
millimeters up to about 2 millimeters (mm) (The next smaller
particle size class below sand size is silt, which is defined as
having a largest dimension ranging from less than about 0.06 mm
down to about 0.004 mm.) As used herein, proppant does not mean or
refer to suspended solids, silt, fines, or other types of insoluble
solid particulate smaller than about 0.06 mm (about 230 U.S.
Standard Mesh). Further, it does not mean or refer to particulates
larger than about 3 mm (about 7 U.S. Standard Mesh).
[0113] The proppant is sufficiently strong, that is, has a
sufficient compressive or crush resistance, to prop the fracture
open without being deformed or crushed by the closure stress of the
fracture in the subterranean formation. For example, for a proppant
material that crushes under closure stress, a 20/40 mesh proppant
preferably has an API crush strength of at least 4,000 psi closure
stress based on 10% crush fines according to procedure API RP-56. A
12/20 mesh proppant material preferably has an API crush strength
of at least 4,000 psi closure stress based on 16% crush fines
according to procedure API RP-56. This performance is that of a
medium crush-strength proppant, whereas a very high crush-strength
proppant would have a crush-strength of about 10,000 psi. In
comparison, for example, a 100-mesh proppant material for use in an
ultra-low permeable formation such as shale preferably has an API
crush strength of at least 5,000 psi closure stress based on 6%
crush fines. The higher the closing pressure of the formation of
the fracturing application, the higher the strength of proppant is
needed. The closure stress depends on a number of factors known in
the art, including the depth of the formation.
[0114] Further, a suitable proppant should be stable over time and
not dissolve in fluids commonly encountered in a well environment.
Preferably, a proppant material is selected that will not dissolve
in water or crude oil.
[0115] Suitable proppant materials include, but are not limited to,
silica sand, ground nut shells, ground fruit pits, sintered
bauxite, glass, plastics, ceramic materials, processed wood,
composite materials, resin coated particulates, and any combination
of the foregoing. Mixtures of different kinds or sizes of proppant
can be used as well.
[0116] In conventional reservoirs, a proppant commonly has a median
size anywhere within the range of about 20 to about 100 U.S.
Standard Mesh. For a synthetic proppant, it commonly has a median
size anywhere within the range of about 8 to about 100 U.S.
Standard Mesh.
[0117] The concentration of proppant in the treatment fluid depends
on the nature of the subterranean formation. As the nature of
subterranean formations differs widely, the concentration of
proppant in the treatment fluid may be in the range of from about
0.03 kilograms to about 12 kilograms of proppant per liter of
liquid phase (from about 0.1 lb/gal to about 25 lb/gal).
[0118] A resinous material can be coated on the proppant. Purposes
of the coating can include improving the strength of a proppant,
changing a wettability characteristic of the proppant for improving
flow of oil or gas, or reducing the migration of a particulate in
the formation that is smaller than the proppant, which can plug
pores in the formation or proppant pack, decrease production, or
cause abrasive damage to wellbore pumps, tubing, and other
equipment.
[0119] The term "coated" does not imply any particular degree of
coverage on the proppant particulates, which coverage can be
partial or complete.
[0120] As used herein, the term "resinous material" means a
material that is a viscous liquid and has a sticky or tacky
characteristic when tested under Standard Laboratory Conditions. A
resinous material can include a resin, a tackifying agent, and any
combination thereof in any proportion. The resin can be or include
a curable resin.
[0121] For example, some or all of the proppant can be coated with
a curable resin. The curable resin can be allowed to cure on the
proppant prior to the proppant being introduced into the well. The
cured resin coating on the proppant provides a protective shell
encapsulating the proppant and keeping the fine particulates in
place if the proppant was crushed or provides a different wettable
surface than the proppant without the coating.
[0122] A curable resin coating on the proppant can be allowed to
cure after the proppant is placed in the subterranean formation for
the purpose of consolidating the proppant of a proppant pack to
form a "proppant matrix." As used herein, "proppant matrix" means a
closely associated group of proppant particles as a coherent mass
of proppant. Typically, a cured resin consolidates the proppant
pack into a hardened, permeable, coherent mass. After curing, the
resin reinforces the strength of the proppant pack and reduces the
flow back of proppant from the proppant pack relative to a similar
proppant pack without such a cured resin coating.
[0123] A resin or curable resin can be selected from natural
resins, synthetic resins, and any combination thereof in any
proportion. Natural resins include, but are not limited to,
shellac. Synthetic resins include, but are not limited to, epoxies,
furans, phenolics, and furfuryl alcohols, and any combination
thereof in any proportion. An example of a suitable commercially
available resin is the EXPEDITE.TM. product sold by Halliburton
Energy Services, Inc. of Duncan, Okla.
[0124] By way of another example, some or all of the proppant can
be coated with a tackifying agent, instead of, or in addition to, a
curable resin. The tackifying agent acts to consolidate and help
hold together the proppant of a proppant pack to form a proppant
matrix. Such a proppant matrix can be flexible rather than hard.
The tackifying-agent-coated proppant in the subterranean formation
tends to cause small particulates, such as fines, to stick to the
outside of the proppant. This helps prevent the fines from flowing
with a fluid, which could potentially clog the openings to
pores.
[0125] Tackifying agents include, but are not limited to,
polyamides, polyesters, polyethers and polycarbamates,
polycarbonates, and any combination thereof in any proportion. An
example of a suitable commercially available tackifying agent is
the SANDWEDGE.TM. product sold by Halliburton Energy Services, Inc.
of Duncan, Okla.
Sand Control and Gravel Packing
[0126] Gravel packing is commonly used as a sand-control method to
prevent production of formation sand or other fines from a poorly
consolidated subterranean formation. In this context, "fines" are
tiny particles, typically having a diameter of 43 microns or
smaller, that have a tendency to flow through the formation with
the production of hydrocarbon. The fines have a tendency to plug
small pore spaces in the formation and block the flow of oil. As
all the hydrocarbon is flowing from a relatively large region
around the wellbore toward a relatively small area around the
wellbore, the fines have a tendency to become densely packed and
screen out or plug the area immediately around the wellbore.
Moreover, the fines are highly abrasive and can be damaging to
pumping and oilfield other equipment and operations.
[0127] Placing a relatively larger particulate near the wellbore
helps filter out the sand or fine particles and prevents them from
flowing into the well with the produced fluids. The primary
objective is to stabilize the formation while causing minimal
impairment to well productivity.
[0128] The particulate used for this purpose is referred to as
"gravel." In the oil and gas field, and as used herein, the term
"gravel" is refers to relatively large particles in the sand size
classification, that is, particles ranging in diameter from about 0
1 mm up to about 2 mm Generally, a particulate having the
properties, including chemical stability, of a low-strength
proppant is used in gravel packing. An example of a commonly used
gravel packing material is sand having an appropriate particulate
size range.
[0129] In one common type of gravel packing, a mechanical screen is
placed in the wellbore and the surrounding annulus is packed with a
particulate of a larger specific size designed to prevent the
passage of formation sand or other fines. The screen holds back
gravel during flow back.
[0130] In some gravel packing applications, a resinous material can
be coated on the particulate. The term "coated" does not imply any
particular degree of coverage on the particulates, which coverage
can be partial or complete.
Frac-Packing
[0131] The combination of a hydraulically-induced fracture with a
gravel-pack completion has been termed a "frac-pac." The primary
purpose of a frac-pac completion is to help eliminate the high
skins often associated with cased-hole gravel packs by providing a
highly conductive flow path through the near-wellbore formation
damaged zone.
Carrier Fluid for Particulate
[0132] A fluid can be adapted to be a carrier fluid for a
particulate.
[0133] For example, a proppant used in fracturing or a gravel used
in gravel packing may have a much different density than the
carrier fluid. For example, sand has a specific gravity of about
2.7, whereas water has a specific gravity of 1.0 at Standard
Laboratory Conditions of temperature and pressure. A proppant or
gravel having a different density than water will tend to separate
from water very rapidly.
[0134] Increasing Viscosity of Fluid for Suspending Particulate
[0135] Increasing the viscosity of a fluid can help prevent a
particulate having a different specific gravity than a surrounding
phase of the fluid from quickly separating out of the fluid.
[0136] A viscosity-increasing agent can be used to increase the
ability of a fluid to suspend and carry a particulate material in a
fluid. A viscosity-increasing agent can be used for other purposes,
such as matrix diversion, conformance control, or friction
reduction.
[0137] A viscosity-increasing agent is sometimes referred to in the
art as a viscosifying agent, viscosifier, thickener, gelling agent,
or suspending agent. In general, any of these refers to an agent
that includes at least the characteristic of increasing the
viscosity of a fluid in which it is dispersed or dissolved. There
are several kinds of viscosity-increasing agents or techniques for
increasing the viscosity of a fluid.
[0138] In general, because of the high volume of fracturing fluid
typically used in a fracturing operation, it is desirable to
efficiently increase the viscosity of fracturing fluids to the
desired viscosity using as little viscosity-increasing agent as
possible. In addition, relatively inexpensive materials are
preferred. Being able to use only a small concentration of the
viscosity-increasing agent requires a lesser concentration of the
viscosity-increasing agent in order to achieve the desired fluid
viscosity.
[0139] Polymers for Increasing Viscosity
[0140] Certain kinds of polymers can be used to increase the
viscosity of a fluid. In general, the purpose of using a polymer is
to increase the ability of the fluid to suspend and carry a
particulate material. Polymers for increasing the viscosity of a
fluid are preferably soluble in the external phase of a fluid.
Polymers for increasing the viscosity of a fluid can be naturally
occurring polymers such as polysaccharides, derivatives of
naturally occurring polymers, or synthetic polymers.
[0141] Water-Soluble Polymers for Increasing Viscosity
[0142] Treatment fluids used in high volumes, such as fracturing
fluids, are usually water-based. Efficient and inexpensive
viscosity-increasing agents for water include certain classes of
water-soluble polymers.
[0143] The water-soluble polymer can have an average molecular
weight in the range of from about 50,000 Da to 20,000,000 Da, most
preferably from about 100,000 Da to about 4,000,000 Da.
[0144] The viscosity-increasing agent can be provided in any form
that is suitable for the particular treatment fluid or application.
For example, the viscosity-increasing agent can be provided as a
liquid, gel, suspension, or solid additive that is incorporated
into a treatment fluid.
[0145] The viscosity-increasing agent should be present in a
treatment fluid in a form and in an amount at least sufficient to
impart the desired viscosity to a treatment fluid. A
viscosity-increasing agent may be present in the fluids in a
concentration in the range of from about 0.01% to about 5% by
weight of the continuous phase therein.
[0146] Problem with Certain Hydratable Materials and Dissolved
Ions
[0147] The commonly used water-soluble viscosity-increasing agents,
water-soluble friction-reducing agents, and water-soluble
elasticity-increasing agents are hydratable. As referred to herein,
"hydratable" means capable of being hydrated by contacting the
hydratable material with water. Regarding a hydratable material
that includes a polymer, this means, among other things, to
associate sites on the polymer with water molecules and to unravel
and extend the polymer chain in the water. It is desirable for
viscosity-increasing agents to be able to be hydrated directly in
the water at the concentration to be used for the fluid.
[0148] A common problem with using hydratable materials is that
many of the commonly-used hydratable materials used for such
purposes are sensitive to dissolved ions in the water. The
hydratable materials are often especially sensitive to divalent
cations such as calcium and magnesium. For example, divalent
cations such as calcium and magnesium can inhibit and slow the time
required for hydration of certain types of polymers commonly used
for such purposes.
[0149] Therefore, fracturing fluids often require the use of water
that does not contain high concentrations of total dissolved
solids, especially high concentrations of dissolved divalent
cations. For this reason, most fracturing fluids require a minimum
quality of water. Most fracturing fluids are run in potable or
freshwater. However, potable water and freshwater is becoming
increasingly expensive and difficult to come by, especially
considering the high volumes of water required for fracturing.
[0150] To solve the problem of hydration in water having high
concentrations of TDS, especially due to high concentration of
divalent cations, another conventional approach has included
chemically modifying the hydratable polymer so that it is better
capable of hydrating in water having high TDS. Other approaches to
handling water having high concentrations of TDS were by chemical
addition to reduce the effect of salt. Another conventional
approach has included heating a brine to about 140.degree. F.
(60.degree. C.) to increase the hydration rate of the hydratable
polymer in the brine. However, heating of brine is time consuming,
expensive, and difficult to achieve in the field. Further, heating
of a brine may cause the viscosity-increasing agent to build
excessive viscosity if later subjected to high wellbore
temperatures. It can be prohibitively expensive to heat large
quantities of water.
[0151] Yet another attempted solution has been to treat the water
to remove some of the interfering ions. There are several existing
methods of treating non-freshwater such as evaporative distillation
and reverse osmosis. Both of these treatment methods remove the
vast majority of TDS from the water. Removing excess ions by
distillation or reverse osmosis is an expensive process. Of course,
the costs of treating water are multiplied by the large volumes of
water required for well treatments, especially for the volumes of
water required for water-fracturing treatments.
[0152] Water Classifications
[0153] Total dissolved solids ("TDS") refers to the sum of all
minerals, metals, cations, and anions dissolved in water. As most
of the dissolved solids are typically salts, the amount of salt in
water is often described by the concentration of total dissolved
solids in the water.
[0154] Freshwater is water containing low concentrations (typically
<1%) of dissolved salts and other total dissolved solids.
[0155] Broadly speaking, "brine" is often understood to be water
containing any substantial concentration of dissolved inorganic
salts, regardless of the particular concentration. Therefore,
"brine" may broadly refer to water containing anywhere from about
1,000 ppm to high percentages of dissolved salts. Brines used for
oil field purposes sometimes contain total dissolved solids of up
to about 10% or higher.
[0156] More technically, however, the terms "brackish water,"
"saline water," "seawater," "brine," and other terms regarding
water may sometimes be used to refer to more precise ranges of
concentrations of TDS.
[0157] Although the specific ranges of TDS for various types of
water are not universally agreed upon, as used herein, the terms
for classifying water based on concentration of TDS will generally
be understood as defined in Table 1.
TABLE-US-00001 TABLE 1 Classification of Water Based on TDS
Concentration and Relationship to Density TDS Concentration Ranges
Density @ 20.degree. C. Water ppm lb/gal (US) g/ml lb/gal (US)
Potable <250 <0.0021 Freshwater <1,000 <0.0083
<0.998 <8.33 Brackish 1,000-15,000 0.0083-0.0417 Saline
15,000-30,000 0.0417-0.1251 Seawater 30,000-40,000 0.1251-0.3338
1.020-1.029 8.51-8.59 Brine >40,000 >0.3338
[0158] Hardness is a more specific measure of the dissolved calcium
(Ca.sup.+2), magnesium (Mg.sup.+2), and ferrous (Fe.sup.+2, a form
of iron) ions in water.
[0159] Water can be classified based on its source. Classifying
water based on its source is independent of the classification
based on a particular parameter, such as TDS.
[0160] Due to a number of factors, the range of TDS concentrations
in naturally-occurring surface water, such as freshwater, brackish
water, saline water, and seawater, can vary considerably within the
defined ranges for the type of water. Water that is not naturally
occurring can be similarly classified by the concentration of TDS,
of course, which is generally with reference to the concentrations
of TDS in the various types of naturally-occurring water.
[0161] Non-potable water that may be suitable for treatment fluids
that include a hydratable polymer that is not sensitive to certain
dissolved ions includes freshwater, brackish water, saline water,
and seawater. Of course, if locally available, brackish water or
seawater is relatively cheap.
[0162] The average composition of seawater, as reported by Karl K.
Turekian, Oceans, 1968, Prentice-Hall, is shown in Table 3.
TABLE-US-00002 TABLE 3 Typical Composition of Seawater
Concentration Dissolved Ion mg/kg (ppm) Chloride (Cl.sup.-) 19,345
Sodium (Na.sup.+) 10,752 Sulfate (SO.sub.4.sup.2-) 2701 Magnesium
(Mg.sup.2+) 1295 Calcium (Ca.sup.2+) 416 Potassium (K.sup.+) 390
Bicarbonate (HCO.sub.3.sup.2-) 145 Bromide (Br.sup.-) 66 Borate
(BO.sub.3.sup.2-) 27 Strontium (Sr.sup.2+) 13 Fluoride (F.sup.-)
1
[0163] A synthetic seawater (ASTM.D1141) has the following
composition: 19359 mg/ml chloride; 2702 mg/ml sulfate; 142 mg/ml
bicarbonate; 11155 mg/ml sodium+potassium; 1297 mg/ml magnesium;
408 mg/ml calcium; TDS=35169 mg/l; pH=8.2.
[0164] It is desirable to be able to use CMHEC in a treatment fluid
for fracturing or gravel packing operations with a brine. In
various embodiments of the disclosed method, the aqueous phase has
at least 1,000 ppm of dissolved divalent cations. The aqueous phase
can have at least 25,000 ppm total dissolved inorganic salts. In
various embodiments, the aqueous phase has less than 100,000 ppm
total dissolved inorganic salts, and more preferably, less than
50,000 ppm total dissolved inorganic salts. Most preferably, the
aqueous phase comprises seawater. In some embodiments, the aqueous
phase comprises seawater without diluting the aqueous phase with
any other source of water.
[0165] Selection of Carboxymethyl Hydroxyethyl Cellulose
(CMHEC)
[0166] Examples of hydration of several aqueous CMHEC-based fluid
wherein the CMHEC has varying degrees of CM-DS and HE-MS
substitutions leads to several critical conclusion about the
relationship of the chemistry of the polymer at the molecular level
and its performance as a fracturing fluid as well as its salt
tolerance in an ionic solution, especially a hard brine such as
seawater: (A) CMHEC with carboxymethyl degree of substitution
(CM-DS) between about 0.3 to about 0.45 per glucopyranose unit in
polymer provides good salt tolerance even in a hard brine such as
seawater and also provides good cross-linking efficiency; and (B)
CMHEC with hydroxyethyl molecular substitution (HE-MS) between
about 2.1 to about 2.8 per glucopyranose unit in polymer provides
good salt tolerance even in a hard brine such as seawater. In
addition, it is believed that random CM-DS is better than block CM
substitution. The CMHEC examples were obtained from a commercial
supplier, which products are conventionally used for hair
conditioner or in the food industry.
[0167] Representative examples are shown in FIGS. 1-3.
[0168] FIG. 1 is a photograph of CMHEC with CM-DS in the range of
about 0.30 to about 0.35 and HE-MS in the range of about 2.1 to
about 2.2 in synthetic seawater on a microscope slide at 60.times.
magnification;
[0169] FIG. 2 is a photograph of CMHEC with CM-DS in the range of
about 0.45 to about 0.6 and HE-MS in the range of about 2.4 to
about 2.6 in synthetic seawater on a microscope slide at 60.times.
magnification; and
[0170] FIG. 3 is a photograph of CMHEC with CM-DS in the range of
about 0.35 to about 0.45 and HE-MS in the range of about 2.8 to
about 2.9 in synthetic seawater on a microscope slide at 60.times.
magnification.
[0171] In various preferred embodiments, the treatment fluid
includes a CMHEC with a with CM-DS in the range of about 0.3 to
about 0.45 and HE-MS in the range of about 2.8 to about 2.9.
[0172] Crosslinking of Polymer to Increase Viscosity of a Fluid or
Form a Gel
[0173] The viscosity of a fluid at a given concentration of
viscosity-increasing agent can be greatly increased by crosslinking
the viscosity-increasing agent. A crosslinking agent, sometimes
referred to as a crosslinker, can be used for this purpose. A
crosslinker interacts with at least two polymer molecules to form a
"crosslink" between them.
[0174] If crosslinked to a sufficient extent, the polysaccharide
may form a gel with water. Gel formation is based on a number of
factors including the particular polymer and concentration thereof,
the particular crosslinker and concentration thereof, the degree of
crosslinking, temperature, and a variety of other factors known to
those of ordinary skill in the art.
[0175] The degree of crosslinking depends on the type of
viscosity-increasing polymer used, the type of crosslinker,
concentrations, temperature of the fluid, etc. Shear is usually
required to mix the base gel and the crosslinking agent. Therefore,
the actual number of crosslinks that are possible and that actually
form also depends on the shear level of the system. The number of
crosslinks is believed to significantly alter fluid viscosity.
[0176] For a polymeric viscosity-increasing agent, any crosslinking
agent that is suitable for crosslinking the chosen monomers or
polymers may be used.
[0177] Cross-linking agents typically comprise at least one metal
ion that is capable of cross-linking the viscosity-increasing agent
molecules.
[0178] Some crosslinking agents form substantially permanent
crosslinks with viscosity-increasing polymer molecules. Such
crosslinking agents include, for example, crosslinking agents of at
least one metal ion that is capable of crosslinking gelling agent
polymer molecules. Examples of such crosslinking agents include,
but are not limited to, zirconium compounds (such as, for example,
zirconium lactate, zirconium lactate triethanolamine, zirconium
carbonate, zirconium acetylacetonate, zirconium maleate, zirconium
citrate, zirconium oxychloride, and zirconium diisopropylamine
lactate); titanium compounds (such as, for example, titanium
lactate, titanium maleate, titanium citrate, titanium ammonium
lactate, titanium triethanolamine, and titanium acetylacetonate);
aluminum compounds (such as, for example, aluminum acetate,
aluminum lactate, or aluminum citrate); antimony compounds;
chromium compounds; iron compounds (such as, for example, iron
chloride); copper compounds; zinc compounds; sodium aluminate; or a
combination thereof.
[0179] Preferably, the source of a polyvalent metal cation is
derived from a water-soluble salt of the polyvalent metal in which
the metal is in the same cationic valence state as the crosslinking
species. By this, it is intended to mean that the metal ion which
forms the crosslinking need not be freshly formed as by a change in
the valence state of the metal ion.
[0180] Where present, the cross-linking agent generally should be
included in the fluids in an amount sufficient, among other things,
to provide the desired degree of cross linking. In some
embodiments, the cross-linking agent may be present in the
treatment fluids in an amount in the range of from about 0.01% to
about 5% by weight of the treatment fluid.
[0181] Buffering compounds may be used if desired, for example, to
delay or control the cross linking reaction. These may include
glycolic acid, carbonates, bicarbonates, acetates, phosphates, and
any other suitable buffering agent.
[0182] Sometimes, however, crosslinking is undesirable, as it may
cause the polymeric material to be more difficult to break and it
may leave an undesirable residue in the formation.
Breaking Viscosity of a Fluid
[0183] After a treatment fluid is placed where desired in the well
and for the desired time, the downhole fluid usually must then be
removed from the wellbore or the formation.
[0184] For example, in the case of hydraulic fracturing, the fluid
should be removed leaving the proppant in the fracture and without
damaging the conductivity of the proppant bed. To accomplish this
removal, the viscosity of the treatment fluid must be reduced to a
very low viscosity, preferably near the viscosity of water, for
optimal removal from the propped fracture. Similarly, when a
viscosified fluid is used for gravel packing, the viscosified fluid
must be removed from the gravel pack.
[0185] Reducing the viscosity of a viscosified treatment fluid is
referred to as "breaking" the fluid. Chemicals used to reduce the
viscosity of treatment fluids are called breakers.
[0186] Breakers for reducing viscosity must be selected to meet the
needs of each situation. First, it is important to understand the
general performance criteria for breaking. In reducing the
viscosity of the treatment fluid to a near water-thin state, the
breaker must maintain a critical balance. Premature reduction of
viscosity during the pumping of a treatment fluid can jeopardize
the treatment. Inadequate reduction of fluid viscosity after
pumping can also reduce production if the required conductivity is
not obtained. A breaker should be selected based on its performance
in the temperature, pH, time, and desired viscosity profile for
each specific treatment.
[0187] In fracturing, for example, the ideal viscosity versus time
profile would be if a fluid maintained 100% viscosity until the
fracture closed on proppant and then immediately broke to a thin
fluid. Some breaking inherently occurs during the 0.5 to 4 hours
required to pump most fracturing treatments. One guideline for
selecting an acceptable breaker design is that at least 50% of the
fluid viscosity should be maintained at the end of the pumping
time. This guideline may be adjusted according to job time, desired
fracture length, and required fluid viscosity at reservoir
temperature.
[0188] A typical gravel pack break criteria is a minimum 4-hour
break time, however, it is still desirable for a gravel-packing
fluid to break within a few days.
[0189] No particular mechanism is necessarily implied by breaking
or breaker regarding the viscosity of a fluid.
[0190] For example, for use a fluid viscosified with a polymeric
material as the viscosity-increasing agent, a breaker can operate
by cleaving the backbone of polymer by hydrolysis of acetyl group,
cleavage of glycosidic bonds, oxidative/reductive cleavage, free
radical breakage, or a combination of these processes. Accordingly,
such a breaker can reduce the molecular weight of the polymer by
cutting the long polymer chain. As the length of the polymer chain
is cut, the viscosity of the fluid is reduced.
[0191] In another example, a breaker may reverse a crosslinking of
a viscosity-increasing agent or attack the crosslinker.
Chemical Breakers
[0192] Chemical breakers used to help clean up a filtercake or
break the viscosity of a viscosified fluid are generally grouped
into several classes: oxidizers, enzymes, chelating agents, and
acids.
[0193] Oxidizers commonly used to reduce viscosity of natural
polymers includes, for example, sodium persulfate, potassium
persulfate, ammonium persulfate, lithium or sodium hypochlorites,
chlorites, peroxide sources (sodium perborate, sodium percarbonate,
calcium percarbonate, urea-hydrogen peroxide, hydrogen peroxide,
etc.), bromates, periodates, permanganates, etc. In these types of
breakers, oxidation reduction chemical reactions occur as the
polymer chain is broken.
[0194] Different oxidizers are selected based on their performance
at different temperature and pH ranges. Consideration is also given
to the rate of oxidation at a particular temperature and pH
range.
[0195] Enzymes are also used to break the natural polymers in oil
field applications. They are generally used at low temperature
25.degree. C. (77.degree. F.) to 70.degree. C. (158.degree. F.) as
at higher temperature they denature and become ineffective. At very
low temperatures, enzymes are not as effective as the rate of
breakage of polymer is very slow and they are generally not
recommended. Different types of enzymes are used to break different
types of bond in the polysaccharides. Some enzymes break only
.alpha.-glycosidic linkage and some break .beta.-glycosidic linkage
in polysaccharides. Some enzymes break polymers by hydrolysis and
some by oxidative pathways. A specific enzyme is needed to break a
specific polymer/polysaccharide. Enzymes are referred to as
Nature's catalysts because most biological processes involve an
enzyme. Enzymes are large protein molecules, and proteins consist
of a chain of building blocks called amino acids. The simplest
enzymes may contain fewer than 150 amino acids while typical
enzymes have 400 to 500 amino acids.
[0196] Acids also provide a break via hydrolysis. Acids, however,
pose various difficulties for practical applications. Acids are not
used as a polysaccharide polymer breaker very often because of
cost, poor break rate control, chemical compatibility difficulties,
and corrosion of metal goods.
[0197] A breaker may be included in a treatment fluid in a form and
concentration at selected to achieve the desired viscosity
reduction at a desired time.
[0198] The breaker may be formulated to provide a delayed break, if
desired. For example, a suitable breaker may be encapsulated if
desired. Suitable encapsulation methods are known to those skilled
in the art. One suitable encapsulation method involves coating the
selected breaker in a porous material that allows for release of
the breaker at a controlled rate. Another suitable encapsulation
method that may be used involves coating the chosen breakers with a
material that will degrade when downhole so as to release the
breaker when desired. Resins that may be suitable include, but are
not limited to, polymeric materials that will degrade when
downhole.
[0199] A treatment fluid can optionally include an activator or a
retarder to, among other things, optimize the break rate provided
by a breaker. Examples of such activators include, but are not
limited to, acid generating materials, chelated iron, copper,
cobalt, and reducing sugars. Examples of retarders include sodium
thiosulfate, methanol, and diethylenetriamine.
[0200] Delayed breakers, activators, and retarders can be used to
help control the breaking of a fluid, but these may add additional
complexity and cost to the design of a treatment fluid.
pH and pH Adjuster or Buffer
[0201] Preferably, the initial pH of the aqueous phase of the
treatment fluid is in the range of about 5 to about 9, and more
preferably in the range of about 7 to 8.5. In an embodiment
including a crosslinker for the CMHEC, however, the initial pH of
the aqueous phase of the treatment fluid is preferably in the range
of about 5 to about 6.5.
[0202] In certain embodiments, the treatment fluids can include a
pH-adjuster. Preferably, the pH adjuster does not have undesirable
properties.
[0203] The pH-adjuster may be present in the treatment fluids in an
amount sufficient to maintain or adjust the pH of the fluid. In
some embodiments, the pH-adjuster may be present in an amount
sufficient to maintain or adjust the pH of the fluid to a pH in the
desired range.
[0204] In general, a pH-adjuster may function, among other things,
to affect the hydrolysis rate of the viscosity-increasing agent. In
some embodiments, a pH-adjuster may be included in the treatment
fluid, among other things, to adjust the pH of the treatment fluid
to, or maintain the pH of the treatment fluid near, a pH that
balances the duration of certain properties of the treatment fluid
(for example the ability to suspend particulate) with the ability
of the breaker to reduce the viscosity of the treatment fluid or a
pH that will result in a decrease in the viscosity of the treatment
fluid such that it does not hinder production of hydrocarbons from
the formation.
[0205] The pH-adjuster may be any other substance known in the art
capable of maintaining the pH in a limited range. One of ordinary
skill in the art, with the benefit of this disclosure, will
recognize the appropriate pH-adjuster and amount thereof to use for
a chosen application.
Optional Encapsulation of Solid Agents for Delayed Release
[0206] Any solid agent can be encapsulated to delay the release of
the solid agent. Encapsulation techniques can be used in
embodiments for controlling the delayed release of a breaker, for
example.
[0207] Solid agents can be encapsulated by any suitable technique
including spray coating a variety of coating materials thereon.
Such coating materials include, but are not limited to, waxes,
drying oils such as tung oil and linseed oil, polyurethanes and
cross-linked partially hydrolyzed polyacrylics. Degradable polymers
such as polyesters, poly lactic acid, and the like may also be used
if desired. A solid agent also may be encapsulated in the form of
an aqueous solution contained within a particulate porous solid
material that remains dry and free flowing after absorbing an
aqueous solution and through which the aqueous solution slowly
diffuses. Examples of such particulate porous solid materials
include, but are not limited to, diatomaceous earth, zeolites,
silica, alumina, metal salts of alumino-silicates, clays,
hydrotalcite, styrene-divinylbenzene based materials, cross-linked
polyalkylacrylate esters, and cross-linked modified starches. In
order to provide additional delay to the release of the solid agent
encapsulated in a particulate porous solid material described
above, an external coating of a polymeric material through which an
aqueous solution slowly diffuses can be placed on the porous solid
material. Examples of such polymeric materials include, but are not
limited to, EDPM rubber, polyvinyldichloride (PVDC), nylon, waxes,
polyurethanes and cross linked partially hydrolyzed acrylics.
Other Fluid Additives
[0208] A treatment fluid can contain additives that are commonly
used in oil field applications, as known to those skilled in the
art. These include, but are not necessarily limited to, inorganic
water-soluble salts, salt substitutes (such as trimethyl or
tetramethyl ammonium chloride), surfactants, defoamers, breaker
aids, oxygen scavengers, alcohols, scale inhibitors, corrosion
inhibitors, hydrate inhibitors, fluid-loss control additives,
oxidizers, chelating agents, water-control agents (such as relative
permeability modifiers), consolidating agents, proppant flowback
control agents, conductivity enhancing agents, clay stabilizers,
sulfide scavengers, fibers, nanoparticles, bactericides, and
combinations thereof.
[0209] Of course, additives should be selected for not interfering
with the purpose of the fluid.
Method of Treating a Well with the Treatment Fluid
[0210] A method of treating a well, is provided, the method
including: forming a treatment fluid according to the disclosure;
and introducing the treatment fluid into the well.
[0211] Designing a Fracturing Treatment for a Treatment Zone
[0212] Fracturing methods can include a step of designing or
determining a fracturing treatment for a treatment zone of the
subterranean formation prior to performing the fracturing stage.
For example, a step of designing can include: (a) determining the
design temperature and design pressure; (b) determining the total
designed pumping volume of the one or more fracturing fluids to be
pumped into the treatment zone at a rate and pressure above the
fracture pressure of the treatment zone; (c) designing a fracturing
fluid, including its composition and rheological characteristics;
(d) designing the pH of the continuous phase of the fracturing
fluid, if water-based; (e) determining the size of a proppant of a
proppant pack previously formed or to be formed in fractures in the
treatment zone; and (f) designing the loading of any proppant in
the fracturing fluid.
[0213] Designing a Gravel Packing Treatment
[0214] Gravel packing methods can include a step of designing or
determining a gravel packing treatment for a treatment zone of the
subterranean formation. According to an embodiment, the step of
designing can include: (a) determining the design temperature and
design pressure; (b) determining the total designed pumping volume
of the one or more treatment fluids to be pumped into the treatment
zone; (c) determining the pumping time and rate; (d) designing the
treatment fluid, including its composition and rheological
characteristics; (e) designing the pH of the continuous phase of
the treatment fluid, if water-based; (f) determining the size of a
gravel; and (g) designing the loading of the gravel in the
fluid.
[0215] Forming Treatment Fluid
[0216] A treatment fluid can be prepared at the job site, prepared
at a plant or facility prior to use, or certain components of the
fluid can be pre-mixed prior to use and then transported to the job
site. Certain components of the fluid may be provided as a "dry
mix" to be combined with fluid or other components prior to or
during introducing the fluid into the well.
[0217] In certain embodiments, the preparation of a treatment fluid
can be done at the job site in a method characterized as being
performed "on the fly." The term "on-the-fly" is used herein to
include methods of combining two or more components wherein a
flowing stream of one element is continuously introduced into
flowing stream of another component so that the streams are
combined and mixed while continuing to flow as a single stream as
part of the on-going treatment. Such mixing can also be described
as "real-time" mixing.
[0218] Introducing the Treatment Fluid into the Treatment Zone
[0219] Often the step of delivering a fluid into a well is within a
relatively short period after forming the fluid, for example, less
within 30 minutes to one hour. More preferably, the step of
delivering the fluid is immediately after the step of forming the
fluid, which is "on the fly."
[0220] It should be understood that the step of delivering a fluid
into a well can advantageously include the use of one or more fluid
pumps.
[0221] Introducing Below or Above Fracture Pressure
[0222] In an embodiment, the step of introducing is at a rate and
pressure below the fracture pressure of the treatment zone. This
can be useful, for example, in a gravel-packing step.
[0223] In an embodiment, the step of introducing comprises
introducing under conditions for fracturing a treatment zone. The
fluid is introduced into the treatment zone at a rate and pressure
that are at least sufficient to fracture the zone.
[0224] Performing a Fracturing Stage
[0225] In general, a fracturing treatment preferably includes
pumping the one or more fracturing fluids into a treatment zone at
a rate and pressure above the fracture pressure of the treatment
zone.
[0226] Monitoring for Fracturing
[0227] Any of the fracturing methods can include a step of
monitoring to help determine the end of a fracturing stage. The end
of a fracturing stage is the end of pumping into a treatment zone,
which can be due to screenout at or near the wellbore or other
mechanical or chemical diversion of fluid to a different treatment
zone.
[0228] One technique for monitoring is measuring the pressure in
the wellbore along the treatment zone. Another technique includes a
step of determining microseismic activity near the zone to confirm
an increase in fracture complexity in the treatment zone.
[0229] Gravel Packing
[0230] In an embodiment, the step of introducing comprises
introducing under conditions for gravel packing the treatment
zone.
[0231] The combination of a hydraulically-induced fracture with a
gravel-pack completion has been termed a "frac-pac." The primary
purpose of a frac-pac completion is to help eliminate the high
skins often associated with cased-hole gravel packs by providing a
highly conductive flow path through the near-wellbore formation
damaged zone.
[0232] Allowing Time for Breaking in the Well
[0233] After the step of introducing the treatment fluid, in an
embodiment the method includes the step of allowing time for
breaking the viscosity of the fluid in the well. This can be
accomplished, for example, by shutting in the treatment zone before
flowing back fluid from the well. The breaking of the viscosity of
the treatment fluid preferably occurs with time under the
conditions in the zone of the subterranean fluid.
[0234] In various embodiments, the treatment fluid is adapted to
break at the design temperature within about 5 days. More
preferably, the treatment fluid is adapted to break within 24
hours. Most preferably, the treatment fluid is adapted to break in
less than 4 hours at the design temperature for the treatment.
[0235] Flow Back Conditions
[0236] In various embodiments, a step of flowing back from the
treatment zone is within about 5 days of the step of introducing.
In another embodiment, the step of flowing back is within about 24
hours of the step of introducing. In some embodiments, the step of
flowing back is within about 4 hours of the step of
introducing.
[0237] Producing Hydrocarbon from Subterranean Formation
[0238] Preferably, after any such use of a fluid according to the
disclosure, a step of producing hydrocarbon from the well or a
particular zone is the desirable objective.
CONCLUSION
[0239] Therefore, the present disclosure is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein.
[0240] The exemplary fluids disclosed herein may directly or
indirectly affect one or more components or pieces of equipment
associated with the preparation, delivery, recapture, recycling,
reuse, or disposal of the disclosed fluids. For example, the
disclosed fluids may directly or indirectly affect one or more
mixers, related mixing equipment, mud pits, storage facilities or
units, fluid separators, heat exchangers, sensors, gauges, pumps,
compressors, and the like used generate, store, monitor, regulate,
or recondition the exemplary fluids. The disclosed fluids may also
directly or indirectly affect any transport or delivery equipment
used to convey the fluids to a well site or downhole such as, for
example, any transport vessels, conduits, pipelines, trucks,
tubulars, or pipes used to fluidically move the fluids from one
location to another, any pumps, compressors, or motors (for
example, topside or downhole) used to drive the fluids into motion,
any valves or related joints used to regulate the pressure or flow
rate of the fluids, and any sensors (i.e., pressure and
temperature), gauges, or combinations thereof, and the like. The
disclosed fluids may also directly or indirectly affect the various
downhole equipment and tools that may come into contact with the
chemicals/fluids such as, but not limited to, drill string, coiled
tubing, drill pipe, drill collars, mud motors, downhole motors or
pumps, floats, MWD/LWD tools and related telemetry equipment, drill
bits (including roller cone, PDC, natural diamond, hole openers,
reamers, and coring bits), sensors or distributed sensors, downhole
heat exchangers, valves and corresponding actuation devices, tool
seals, packers and other wellbore isolation devices or components,
and the like.
[0241] The particular embodiments disclosed above are illustrative
only, as the present disclosure may be modified and practiced in
different but equivalent manners apparent to those skilled in the
art having the benefit of the teachings herein. It is, therefore,
evident that the particular illustrative embodiments disclosed
above may be altered or modified and all such variations are
considered within the scope of the present disclosure.
[0242] The various elements or steps according to the disclosed
elements or steps can be combined advantageously or practiced
together in various combinations or sub-combinations of elements or
sequences of steps to increase the efficiency and benefits that can
be obtained from the disclosure.
[0243] It will be appreciated that one or more of the above
embodiments may be combined with one or more of the other
embodiments, unless explicitly stated otherwise.
[0244] This illustrative disclosure can be practiced in the absence
of any element or step that is not specifically disclosed or
claimed.
[0245] Furthermore, no limitations are intended to the details of
composition, design, or steps herein shown, other than as described
in the claims.
* * * * *